1. Field of the Invention
The invention relates generally to earth-boring drill bits used to drill a borehole for the ultimate recovery of oil, gas, or minerals. More particularly, the invention relates to drag bits and to improved stabilizing features for such bits. Still more particularly, the present invention relates to arrangements of stabilizing members on drag bits that trail corresponding cutter elements on the bit and engage the ridge of uncut formation between radially adjacent cutter elements to enhance bit stability.
2. Background of the Invention
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole thus created will have a diameter generally equal to the diameter or “gage” of the drill bit.
Many different types of drill bits and cutting structures for bits have been developed and found useful in drilling such boreholes. Two predominate types of drill bits are roller cone bits and fixed cutter bits, also known as rotary drag bits. Some fixed cutter bit designs include primary blades, secondary blades, and sometimes even tertiary blades, angularly spaced about the bit face, where the primary blades are generally longer and start at locations closer to the bit's rotating axis. The blades generally project radially outward along the bit body and form flow channels there between. In addition, cutter elements are often grouped and mounted on several blades. The configuration or layout of the cutter elements on the blades may vary widely, depending on a number of factors. One of these factors is the formation itself, as different cutter element layouts engage and cut the various strata with differing results and effectiveness.
The cutter elements disposed on the several blades of a fixed cutter bit are typically formed of extremely hard materials and include a layer of polycrystalline diamond (“PCD”) material. In the typical fixed cutter bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of one of the several blades. In addition, each cutter element typically has a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. The cutting layer is exposed on one end of its support member, which is typically formed of tungsten carbide. For convenience, as used herein, reference to “PDC bit” or “PDC cutter element” refers to a fixed cutter bit or cutting element employing a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide.
While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the face of the drill bit. The fixed cutter bit typically includes nozzles or fixed ports spaced about the bit face that serve to inject drilling fluid into the flow passageways between the several blades. The flowing fluid performs several important functions. The fluid removes formation cuttings from the bit's cutting structure. Otherwise, accumulation of formation materials on the cutting structure may reduce or prevent the penetration of the cutting structure into the formation. In addition, the fluid removes cut formation materials from the bottom of the hole. Failure to remove formation materials from the bottom of the hole may result in subsequent passes by cutting structure to re-cut the same materials, thereby reducing the effective cutting rate and potentially increasing wear on the cutting surfaces. The drilling fluid and cuttings removed from the bit face and from the bottom of the hole are forced from the bottom of the borehole to the surface through the annulus that exists between the drill string and the borehole sidewall. Further, the fluid removes heat, caused by contact with the formation, from the cutter elements in order to prolong cutter element life. Thus, the number and placement of drilling fluid nozzles, and the resulting flow of drilling fluid, may significantly impact the performance of the drill bit.
Without regard to the type of bit, the cost of drilling a borehole for recovery of hydrocarbons may be very high, and is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed before reaching the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is desirable to employ drill bits which will drill faster and longer, and which are usable over a wider range of formation hardness.
The length of time that a drill bit may be employed before it must be changed depends upon a variety of factors. These factors include the bit's rate of penetration (“ROP”), as well as its durability or ability to maintain a high or acceptable ROP.
Excessive wear of cutter elements and damage to cutter elements resulting from impact loads detrimentally impact bit ROP. Excessive wear and damage to cutter elements may arise for a variety of reasons. For example, in a soft formation layer, the cutter elements can often sustain a relatively large depth-of-cut (DOC) and associated high ROP. However, as the bit transitions from the soft formation layer to a hard formation layer, such a large depth-of-cut typically result in abrupt and unpredictable impact loads to the cutter elements, which increases the likelihood of excessive wear of the cutter elements, breakage/fracture of the cutter elements, and/or delamination of the cutter elements. As another example, instability and vibrations experienced by a downhole drill bit may result in undesirable impact loads to the cutter elements, which may chip, break, delaminate, and/or excessively wear the cutter elements. Such excessive wear and damage resulting from impact loads experienced by cutter elements typically results in a reduced ROP for a given weight-on-bit (WOB). Further, in many cases, such damage to the cutter elements is not recognized at the surface as the drilling rig attempts to further advance the bit into the formation with increased weight-on-bit (WOB), potentially damaging the bit beyond repair.
Bit balling and formation packing off can also detrimentally impact bit ROP. In particular, as formation is removed by cutter elements, drilling fluid from the bit's nozzles flushes the formation cuttings away from the bit face and up the annulus between the drill string and the borehole wall. As previously described, while drilling through soft formations the cutter elements can sustain a relatively high depth-of-cut and ROP, which results in a relatively high volume of formation cuttings. If the volume of formation cuttings is sufficiently large, the nozzles may not provide sufficient cleaning of the bit face, potentially leading to plugging of the nozzles and the junk slots between the blades by the formation cuttings (i.e., bit “balling”). In addition to bit balling, an excessive depth-of-cut may decrease the steerability of the drill bit, thereby reducing effective ROP in directional drilling applications. In particular, with a large depth-of-cut, the drill bit must be continuously steered to keep the bit on course to limit and/or prevent the bit from “straying” off course.
Accordingly, there remains a need in the art for a fixed cutter bit and cutting structure capable of enhancing bit stability, bit ROP, and bit durability. Such a fixed cutter bit would be particularly well received if it offered the potential to limit the depth-of-cut of the cutter elements to reduce the potential for abrupt impact loads and bit balling, while allowing for enhanced steerability.